Various methods are known for fracturing a subterranean formation to enhance the production of fluids therefrom. In the typical application, a pressurized fracturing fluid hydraulically creates and propagates a fracture. The fracturing fluid carries proppant particulates into the extending fracture. When the fracturing fluid is removed, the fracture does not completely close from the loss of hydraulic pressure; instead, the fracture remains propped open by the packed proppant, allowing fluids to flow from the formation through the proppant pack to the production wellbore.
The success of the fracturing treatment may depend on the ability of fluids to flow from the formation through the proppant pack. In other words, the proppant pack or matrix must have a high permeability relative to the formation for fluid to flow with low resistance to the wellbore. Furthermore, the surface regions of the fracture should not be significantly damaged by the fracturing to retain fluid permeability for optimal flow from the formation into the fracture and the proppant pack.
The prior art has sought to increase the permeability of the proppant pack by increasing the porosity of the interstitial channels between adjacent proppant particles within the proppant matrix. For example, US200600408944A1 (van Batenburg, et al.) discloses a method of forming a high porosity propped fracture with a slurry that includes a fracturing fluid, proppant particulates and a weighting agent. These prior art technologies seek to distribute the porosity and interstitial flow passages as uniformly as possible in the consolidated proppant matrix filling the fracture, and thus employ homogeneous proppant placement procedures to substantially uniformly distribute the proppant and non-proppant, porosity-inducing materials within the fracture.
As another example, in US20060048943A1 (Parker, et al.) proppant particulates and degradable material do not segregate before, during or after injection to help maintain uniformity within the proppant matrix. Fracturing fluids are thoroughly mixed to prevent any segregation of proppant and non-proppant particulates. In another approach, non-proppant materials have a size, shape and specific gravity similar to that of the proppant to maintain substantial uniformity within the mixture of particles in the fracturing fluid and within the resulting proppant pack. A tackifying compound coating on the particulates has also been used to enhance the homogenous distribution of proppant and non-proppant particulates as they are blended and pumped downhole into a fracture.
A recent approach to improving hydraulic fracture conductivity has been to try to construct proppant clusters in the fracture, as opposed to constructing a continuous proppant pack. U.S. Pat. No. 6,776,235 (England) discloses a method for hydraulically fracturing a subterranean formation involving alternating stages of proppant-containing hydraulic fracturing fluids contrasting in their proppant-settling rates to form proppant clusters as posts that prevent fracture closing. This method alternates the stages of proppant-laden and proppant-free fracturing fluids to create proppant clusters, or islands, in the fracture and channels between them for formation fluids to flow. The amount of proppant deposited in the fracture during each stage is modulated by varying the fluid transport characteristics (such as viscosity and elasticity), the proppant densities, diameters, and concentrations and the fracturing fluid injection rate. However, the positioning of the proppant-containing fluid is difficult to control. For example, the proppant-containing fluid can have a higher density than the proppant-free fluid and can thus underride the proppant-free fluid. This underride can result in non-uniform distribution of proppant clusters, which in turn can lead to excessive fracture closure where there is not enough proppant and constricted flow channels where there is too much proppant.